Vibratory Drilling System and Tool For Use In Downhole Drilling Operations and A Method For Manufacturing Same

ABSTRACT

A vibratory drilling tool for use coupling to a drill string in a borehole in downhole drilling operations has a tool body having a fluid flow path extending along a longitudinal axis there through, a first pin end and an opposite box end. A cam body portion extending longitudinally along the length of said tool has a generally smooth cam arc section on an opening side with at least one elongated flat surface extending longitudinally along a closing side of the cam body portion from a pin end tapering shoulder to a box end tapering shoulder. The cam body portion when coupled to said drill string lifts a generally horizontal drill pipe section of the drill string vertically in the borehole as the drill pipe section is rotated in the borehole.

This application claims priority to U.S. Provisional Patent ApplicationSer. No. 61/620,043 filed Apr. 4, 2012, which is incorporated byreference herein for all purposes.

BACKGROUND OF THE INVENTION

During the last twenty years horizontal drilling technology has improvedtremendously with the ability to extend farther into oil and gasformations. The ability of the industry to expose untold oil and gasreserves for potential marketing has launched unprecedented activity inthe new and older oil and gas fields of the US and other places.Unfortunately the ability to drill horizontally with state of the artsteering tools, new drill bit designs, exotic drilling fluid systems,etc., have still not addressed the most expensive problem in horizontaldrilling, “getting the cuttings out of the wellbore and maintaining acontrolled amount of weight to the drill bit”. It is to these twocombined problems that the present invention addresses.

Any deviated or horizontal wellbore has a problem of keeping theformation cuttings suspended in the drilling fluid and from falling outof the mud system onto the bottom of the wellbore. Many attempts havebeen made to keep the cuttings in the drilling fluid system via,water-based mud, oil-based mud, synthetic mud systems and mechanicalmanipulation of the drill string and mud pump pressure. Additionalmechanical attempts have been made with drilling tools that provideextreme vibrations to the drill string via variations in drill mudpressures. These extreme vibrations have to be cushioned by other toolsto insulate the vibrations at the surface to prevent damage to thedrilling rig and expensive steering tools.

As the wells extend farther into the formation, the ability to deliverweight from the vertical section of the drill string and transmit itthrough the horizontal length of the drill string for application ofweight to the drill bit is impeded. The most significant problem is thatcuttings traveling from the drill bit will fall out of the mud systemand stack up on the bottom of the borehole thereby reducing the volumecapacity of the previously drilled section of the wellbore.. Accordingto some industry experts, cuttings typically fall out every 20 to 30feet. Consequently, other problems begin to occur when this stackinghappens. For example, restrictive hole size begins to impose extremefriction on the drill string in the lateral section and causes increasedback pressure from the returning drilling fluid invades the previouslydrilled sections of the wellbore. Catastrophic problems may occurincluding lost circulation, formation swelling, and fracturing of theformation. The end result of all these issues may lead to lost drillstrings and loss of the wellbore.

The present invention provides a system and tool that improves cuttingssuspension to the mud system while improving this transition ofcontrolled and steady weight through the lateral section of the drillstring to the drill bit. Refurbishing costs are low and, moreimportantly, there are no moving parts in the tool itself other than therotation of the number of cams rotating with the drill string.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A illustrates a top, rear perspective view of the presentvibratory tool with wiping fingers attached.

FIG. 1B shows a top, front perspective view of the tool of FIG. 1A.

FIG. 2A illustrates a side elevation, cross-sectional view of thepresent vibratory tool without wiping fingers.

FIG. 2B shows a cross-sectional view taken along the A-A of FIG. 1A.

FIG. 2C illustrates a top, front perspective view of the embodiment ofthe tool with a threaded portion along the cam body at the cam apexintersection with a flat section.

FIG. 2D shows a side elevation perspective view of the embodiment ofFIG. 2C

FIG. 2E shows a cross-sectional view of the embodiment of FIG. 2D.

FIG. 3 is a cross-sectional end view of the present vibratory tool witha wiping finger installed.

FIG. 4 shows a partial, top plan view of the large flat on the cam ofthe present vibratory tool with opening to receive the wiping fingers.

FIG. 5A illustrates a cross-sectional view of the tool in a boreholewith the apex of the cam at the top (90 degree position) of a horizontalwellbore.

FIG. 5B illustrate the tool of FIG. 5A rotated about 180 degrees in theborehole with the cam at approximately the bottom (278 degree position)of the horizontal wellbore.

FIG. 5C illustrates the tool of FIG. 5A rotated about 270 degrees in theborehole with the cam at approximately the 360 degree position of thehorizontal wellbore.

FIGS. 6A-6H illustrate the displacement of the center point of the toolas it rotates, lifts, and cleans within the borehole.

FIG. 7 shows a sketch of a typical prior art horizontal drill string.

FIG. 8 illustrates a sketch of a horizontal drilling operation with adrill string incorporating the present vibratory tool.

FIG. 9 is an illustration of a rotating drill pipe section (with thepresent vibratory tool) deflecting within a horizontal wellbore as thecam lifts the drill string from the bottom of the borehole allowingcritical hold volume to effect the bottom of the wellbore and movecuttings back into the flow stream.

FIG. 10A is a top, rear perspective view of a section of standard drillpipe or heavy weight pipe having a raised wear joint retrofitted toincorporate the cam-shaped structure of the present vibratory tool.

FIG. 10B is a top, front perspective view of the section of standarddrill pipe of FIG. 10A having a raised wear joint retrofitted toincorporate the cam-shaped structure of the present vibratory tool.

FIG. 10C is a cross-sectional view of the retrofitted drill pipe of FIG.10A taken along line A-A.

FIG. 11 illustrates in cross-section an alternative embodiment of thevibratory tool showing a plurality of cam elements incorporated into asingle tool profile.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

As may be seen in the various Figures, a short and single body tooljoint 20 with a unique cam-shaped profile 22 on the cam body 28 whichraises and lowers the drill pipe within the borehole during drill stringrotation. (See FIGS. 8 and 9.) The cam-body has a generally smooth,consistent, arc section along the opening side. The closing side of thecam body 28 is provided with one or more flat surfaces of varyingwidths. This unique modification of a traditional pear-shape cam profileon the cam body creates vibratory action of the drill string bothvertically and horizontally generally about the center point 112 of theborehole. The vibratory action is also transmitted laterally along thedrill string.

Additionally, in one embodiment of the tool (FIGS. 2C-2E), the cam body28 is provided with a threaded portion 200 extending along theintersecting edge 202 of the apex 42 of the cam body with a flat section28 of the cam body 28. The threaded portion 200 has course and shallowthreads (depth approximately 0.025″) that extend only 2″-4″ along edge202. The threads thin out as they spiral toward the smaller diameter ofthe cam body 28. The thread portion results in momentary forward urgingof the drill string toward the drill bit and provides mechanicalscrapping of cuttings from the bottom of the wellbore when the threadedportion reaches the bottom of the well bore during rotation.

Optimum fluid volume is maintained around the outside of the cam profileto allow drilling fluid 46 to pass and create turbulence; therefore,thrusting cuttings back into the mud system for evacuation.

The cam body 28 with a generally, smooth, consistent opening side 500arc section and flat sections 25, 34 and 36 on the closing side 502 ofthe cam body 28 causes a lifting of the drill string and a uniquedisplacement of the tool center point 112 of the borehole creating anoscillating, harmonic rotation, or vibratory motion of the drill stringas will be described further below (FIGS. 6A-6H). The threaded portion200 along the length of the cam body further causes a momentary,forward-urging or lurching of the drill string when the edge 202 reachesthe bottom cuttings in the wellbore.

The intersection of flats 26, 31, and 36 on the cam body 28 provideseveral feeding edges 202, 204, and 206 to cause a mechanical, steppedscraping of the cuttings on the bottom of the hole while optional wipingfingers 24 thrust the cuttings hack into the mud system without alteringthe bottom of the lateral wellbore.

The incorporation of short replaceable wiping fingers 24 that may bethreaded into the long flat 26 on the earn are positioned such that theydo not create a “pinch point” with the wellbore.

The wiping fingers 24 may be quickly replaced on the rig floor duringtrips after approximately 150 to 200 hours of operation. The flat areasof the cam profile with the leading edges 202, 204, and 206, provide agentle systematic scrapping of the bottom of the well here withoutadding additional rotational friction to the drill string.

A plurality of tools 20 with cam bodies 28 instated along the drillstring will create a continuous oscillation or “harmonic rotation” ofthe lateral section of the drill string in the deviated or horizontalwellborn which improves the turbulence of the mud system and helps keepthe cuttings from dropping not onto the bottom of the wellbore. Theoscillation also improves well bore stability by imbedding cuttings anddebris into the outer sides of the wall of the borehole forming astrengthening, composite boundary layer around the wellbore (FIGS. 7, 8and 9). This boundary layer naturally occurs when drilling the verticalsection of the well but has not been available along the horizontalsection until the utilisation of the present vibratory tool.

It should be understood that as the cam body 28 raises and lowers thedrill string vertically every revolution this causes an intermittentlengthening and shortening of the drill string length to some degree andcreates a “weight pulse effect” that helps maintain a constant slidingaction of the drill string, thereby, influencing constant transmissionof weight to the drill bit. The present vibratory tool may be utilizedwith drilling speeds from 20 rpm to 130 rpm. Ideally best vibratoryaction may be achieved in the 40-60 rpm range, but it is anticipatedthat rotation rates of 120 rpm may not be uncommon.

During installation of a vibratory tool 20 of the present design at therig floor, the rotary table may locked and after torqueing each cammedsection 20 into the drill string, the position of the cam apex 42 may berecorded, referencing the degree of the apex to the degrees of therotary table. This cam apex position profile will insure the position ofall the cams in relation to the steering tools when there is the needfor “sliding” operations (moving the string without rotation of thestring). The profile will also help analyse and vary the amount ofoscillation or vibratory potential of the lateral section. Some range oftorqueing ability helps to position the cam apexes during assembly foran even distribution of cam apexes in degrees from each other.

Turning to the figures and illustrations, FIG. 1A shows a top, rearperspective view of the present vibratory tool 20 having a cam bodyportion 28 with a modified pear-shaped cam profile 22. A plurality ofwiping fingers 24 extend outwardly from a first, wide flat surface 26 onthe closing side of the cam body 28. The pin end 30 of the tool 20 isopposite the box end 32 of the tool 20. As may be seen in FIG. 1A. Inaddition to flat surface 25, two other flat surfaces 34 and 36 each ofwhich may have a varying width are formed slang the enter surface of thecam body 28 each flat surface extending longitudinally from pin endtapering shoulder 38 to box end tapering shoulder 40. It should beunderstood that fingers 24 may be provided in the flat surfaces 34 and36

The shoulders gradually taper from the tool body surface 23 of thecylindrical body portion 21 to the top surface at the apex 42 ofcam-shaped body portion 28. The tapering shoulders 38 and 40 providesmooth fading and trailing surfaces as the tool is moved longitudinallythrough the horizontal borehole.

FIG. 1B illustrates a top, front perspective view of the tool of FIG.1A. The smooth, consistent, opening side arc section of the cam profile22 on the cam body 28 is clearly illustrated as are the taperingshoulders 38, 40 and surface 23.

Turning to FIGS. 2A and 2B, it may be seen that the tool 20 has alongitudinal axis L-L running the length of the tool. The tool has acylindrical body portion 21 and a cylindrical tool body surface 23. Thebody portion 21 has an internally threaded section 300 at the box end 32so that it may be coupled to a first drill string section. An opposite,pin end 30 has an externally threaded section 302 for coupling toanother section of the drill string. The distance r1 from the toolcenter point 50 to the tool body surface 23 is less than the distance r2from the center point 50 of the tool to the apex 42 of the cam bodyportion 28 (FIG. 2B). Some typical dimensions are noted on FIG. 2A. Itshould be understood that proportionally larger or small tools 20 couldbe made depending on the size of the wellbore and other drillingrequirements.

In FIG. 2B a cross-sectional view of the embodiment of FIG. 2A is shown.The various flat surfaces 26, 34, and 36 of varying widths on theclosing side 502 of the cam body 28 are illustrated in relation to thesmooth, consistent arc section 19 on the opening side of cam body 28.Typical dimensions are again provided on FIG. 2B.

FIG. 2C illustrates a top, front perspective view of an embodiment ofthe tool 20 with a threaded portion 200 extending along the intersectingedge 202 at the apex 42 of the cam body 28 with a flat section 26 of thecam body 28. The threaded portion 200 has course and shallow threads(depth approximately 0.025″) that extend only 2″-4″ along edge 202. Thethreads thin out as they spiral toward the smaller diameter of the cambody 28. The thread portion results in momentary forward urging of thedrill string toward the drill bit and provides mechanical scrapping ofcuttings from the bottom of the wellbores when the threaded portionreaches the bottom of the well bore during rotation.

Additional FIG. 2D shows a side elevation perspective view of theembodiment of FIG. 2C with the threaded portion 200 along the edge ofthe intersection of the cam arc section 19 of the cam body 28 and theflat section 26.

FIG. 2E shows a cross-sectional view of the embodiment of FIG. 2D.

A cross sectional view of the tool of FIG. 2D is shown in FIG. 2E. Thethreaded edge 202 is shown at the apex 42 of the cam body 28.

FIG. 3 shows a cross-sectional end view of the present vibratory tool 20with a wiping finger 24 installed in opening 27 in flat surface 26. Thefingers may be of wire cable material or the like and threaded on oneend for retention in opening 27. The rear access of the openings 27 aallows a suitable wrench or tool to be inserted to tighten or loosen thefingers for installation or replacement.

FIG. 4 shows a partial, top plan view of the large flat surface 26 onthe cam body 28 of the present vibratory tool 20 with opening 27 toreceive the wiping finger 24. The openings are set at a 30 degree angleto the face of the flat 26.

FIG. 5A illustrates a cross-sectional view of the tool 20 in a boreholewith the apex 42 of the cam body 28 at the top (90 degree position) of ahorizontal wellbore 43. Drilling mod 46 with suspended cuttings 48 isshown in the borehole.

It should be noted in FIG. 5A that the tool 20 is generally resting nearthe bottom of the wellbore. As the tool begins to rotate clockwise, thetool will shift left and upwardly in the borehole. In FIG. 5A thefingers 27 see fully extended and almost touch the top side of theborehole. Further, note the center point 50 of the tool in relation tothe center 112 of the wellbore. This center point 50 will move abruptlyas the tool rotates creating a shifting movement of the tool within theborehole. The shifting motion creates turbulence in the drilling mudkeeping the cuttings suspended in the mud. As the tool rotates, thefingers 27 sweep inside the borehole thereby thrusting the cuttingsalong the drill string for evacuation.

FIG. 5B illustrates the tool of FIG. 5A rotated about 180 degrees in theborehole with the cam apex 42 at approximately the bottom (278 degreeposition) of the horizontal wellbore. The intersecting edge 204 formedalong the intersection of flat surfaces 34 and 36 moves closely alongthe inner wall of the borehole and causes cuttings 48 to be displacesand suspended in the drilling mud 46. In FIG. 5B the fingers 24 haveflexed are sweeping cuttings 48. The center point 50 of the tool 20 hasmoved upwardly and to the right as the tool oscillates and rotateswithin the borehole.

FIG. 5C illustrates the tool 20 of FIG. 5A rotated about 270 degrees inthe borehole with the cam apex at approximately the 360 degree positionof the horizontal wellbore. Again the center point 50 has moved withinthe borehole causing the tool to shift creating vibration in the drillstring.

FIGS. 6A-6H illustrate the displacement of the center point 50 of thetool as it rotates within the borehole. The center of the borehole isshown at 112. The apex 42 of the tool is shown rotating from 12 o'clock(90 degrees) in FIG. 6A through 1:30 o'clock in FIG. 68 to 3:00 o'clock(180 degrees) in FIG. 6C. FIG. 6C shows that the tool beginning to liftin the wellbore. The lifting continues with the rotation of the tool asseen in FIG. 6D where the apex 42 is shown at about 4:30 o'clock. Whenthe tool has rotated to about 6:00 o'clock (270 degrees) a jarring ofthe tool is created as the tool 20 with flats 31 and 36 falls toward thewellbore bottom (FIG. 6E) after having been earlier lifted. Cleaning ofthe cuttings along the wellbore is shown in FIGS. 6F-6G, as the toolcontinues to rotate and intersecting edges 202, 204, and 206 move alongthe bottom of the wellbore.

FIG. 7 snows a sketch of a typical prior art horizontal drill string 400with a generally vertical section 402 that applies weight to the drillbit 404. Drill pipe tool connections 406, wear joints 408, steeringtools 405, and the drill hit 404 are shown. Tool joints and wear jointson the bottom of the lateral tend to restrict delivery of weight todrill bit (WOB) as shown at numeral 410. Cuttings fall out atapproximately 1000 feet forming beds that further restrict WOB, adddrag, torque, and possible pipe sticking as seen at numeral 412.

FIG. 8 illustrates a sketch of a horizontal drilling operation with adrill string incorporating the present vibratory tool 20 at 500′intervals. Penetration rates of approximately 300′ per hour areachievable in shale formations. FIG. 8 reflects that one cam tooltravels the 500′ approximately 1 hour 40 minutes. Further, as may beseen in FIG. 8, the drill string lifts and allows for cuttings to becirculated in a turbulent flow zone TFZ in the proximity of the tool 20.

FIG. 9 is an illustration of a rotating drill pipe section (with thepresent vibratory tool 20) deflecting within a horizontal wellbore asthe cam body 28 lifts the drill string from the bottom of the borehole.

FIG. 10A is a top, front perspective view another embodiment of thepresent vibratory tool 20 b on a section of standard drill pipe or heavyweight pipe 300 having a raised wear joint 60. The pipe 300 isretrofitted or refurbished to incorporate a cam-shaped structure 28 b aswill be described in FIG. 10C.

FIG. 10B is a top, back perspective view of the section of standarddrill pipe or heavy weight pipe of FIG. 10A having a raised wear joint60 retrofitted or refurbished to incorporate the cam-shaped structure 28b of the present vibratory tool 20 b.

FIG. 10C is a cross-sectional view of the retrofitted drill pipe of FIG.10A taken along line 10C-10C. A cam profile member 70 is welded to thewear joint 60 as is a flat profile member 72. This creates a cam body 28b with a smooth, cam section 19 a on the opening side of the cam body 28b Other fiats may be cut or machined in the wear joint 60 asappropriate. FIG. 10C also shows the drill pipe inside diameter 62 and adrilling fluid volume 46 within the wellbore 80.

FIG. 11 illustrates in cross-section an alternative embodiment of thevibratory tool 20 c showing a plurality of cam elements 28 cincorporated into a single tool profile. While FIG. 11 shows theplurality on a pipe wear joints 60, it is understood that multiple camsmay be formed on a single tool as shown in earlier figures. In FIG. 11,the wear joint 60 has two cam profile members 70 and two flat members 72affixed to the joint. Weld build ups 73 are applied and ground to createa smooth transition of the tool profile.

The flowing data is provided to illustrate a formula to calculate theeffectiveness of the vibratory tool 20.

EXAMPLE ONE (Refer to FIG. 8 for Understanding)

Vertical Section of the well=6,000 ft.

Curve=90 degrees@1000 ft.

Lateral Section=4,000 ft.

6⅛″ Wellbore

3½″ Drill Pipe with 4¾″ Tool Joints

Using (6) vibratory tools 20 spaced 500″ apart, beginning 1,000 ft. fromthe drill bit and steering tools.

50 to 60 RPMs; 250 GPMs; 1,800 PSI Pump Pressure; PDC Drill Bit

Lateral Section Tool Joint Friction Formula=3,000 ft. divided by 31′average joint length=96 joints. 96 joints divided by (6) tools. Tools 20spaced every 16 joints.

Each lateral joint of pipe has a middle section or wear joint (DUDs)that resembles a tool joint but is solid material and is lying on thebottom of the wellbore also causing drag. So, additional 96 (DUDs)=192total (joints) lying on the bottom of the wellbore. Each tool 20 raisesitself, (deflects) and two opposing DUDS which are 15 ft. from eachtorqued tool joint. (6) tools×(3) joints=(18) joints that aremomentarily raised from the bottom of the well bore 40 to 60 time perminute, (RPMs). 192 total joints divided by 18 (joints)=10.6% reduceddrag 40 to 00 times per minute.

Cutting Removal Formula:

Each tool 20 distributes cuttings back into the mud system 40 to 70times per minute. 96 joints divided by (6) tools 20=16% cuttingssuspension improvement and cleans the bottom of the well bore.

Constant Weight to Bit Formula:

Each tool 20 positioned 500 ft. apart will deflect drill string ¾ of aninch, (shortening and lengthening) the length of immediate 30 ft.section of drill pipe either side of the tool 20. Total effectedlength=360 ft. divided by 31′=11.6 joints. 96 total joints divided by11.6 joints=8.27% Improved weight transmission to drill bit by weightpulse action.

Vibration Formula: Tools 20 placed every 500 ft., will rock 60 ft. eachside of tool. Same formula as above wherein 96 total joints divided by11.6 joints=8.27% improvement.

Whipping or Oscillation Formula: Each tool placed every 500 ft. willhave an effective whipping area of 60 ft. each side of tool. This actionwill increase fluid turbulence to pick up cuttings. Same formula asshove wherein 96 joints divided by 11.6 joints=8.27%.

Accumulative Improvement on All Issues:

Friction 10.6% Cutting Removal   16% Constant Weight 8.27% Vibration8.27% Whipping Formula 8.27% Total Lateral Issues Improvement = 51.41% 

NO assumptions have been made in this example pertaining to the obviousimprovements the present tool will effect penetration rates, reductionin water loss, rig time, water and drilling fluid usage, hole problems,environmental impact of oil based system maintenance and the expensesincurred, redaction of steering runs by improved hole conditions, andother issues.

If formulas are correct and 51% improvement is achieved then penetrationrates will improve dramatically causing more cuttings in the holequicker. This would give obvious need for additional vibratory tools toaccommodate the influx. Ultimately, with enough vibratory tools 20 inthe hole, it may be assumed that lateral drilling may become ascontrolled as the vertical section of the well.

Although the invention has been described with reference to specificembodiments, the description is not meant to be construed in a limitedsense. Various modifications of the disclosed embodiments, as well asalternative embodiments of the invention will become apparent to personsskilled in the art upon the reference to the description of theinvention. It is, therefore, contemplated that the appended claims willcover such modifications that fall within the scope of the invention.

1. A vibratory drilling tool for use in a generally deviated orhorizontal section of a borehole in downhole horizontal drillingoperations comprising: a tool body having a fluid flow path extendingalong a longitudinal axis therethrough said longitudinal axis of saidtool body being generally parallel to a longitudinal axis of saidgenerally deviated or horizontal section of said borehole, a first pinend and an opposite box end for coupling said tool body to a drillstring; a cam body portion extending longitudinally along a length ofsaid tool having a generally smooth cam arc section on an opening sidewith at least one elongated flat surface extending longitudinally alonga closing side of said cam body portion from a pin end tapering shoulderto a box end tapering shoulder, said cam body portion vertically liftinga generally horizontal drill pipe section of said drill string in saidgenerally deviated or horizontal section of said borehole when said toolbody is coupled to said drill string and said drill pipe section isrotated in said borehole.
 2. The vibratory tool of claim 1 furthercomprising a threaded portion along an edge of an intersection of saidcam arc section and said at least one elongated flat surface of said cambody portion.
 3. The vibratory tool of claim 1, further comprising aplurality of flat surfaces extending longitudinally along said closingside of said cam body portion from said pin end tapering shoulder tosaid box end tapering shoulder.
 4. The vibratory tool of claim 2 whereina plurality of scrapping edges extend longitudinally along intersectionsof said flat surfaces.
 5. The vibratory tool of claim 1, furthercomprising a plurality of wiping fingers extending outwardly from atleast one of said elongated flat surface.
 6. A vibratory drilling systemcomprising: a drill string for use in a generally deviated or horizontalsection of a borehole in downhole horizontal drilling operations havinga plurality of drill pipe sections, a steering tool, and a drilling bitwherein at least one of said plurality of drill pipe sections furthercomprises: a drill pipe body portion having a fluid flow path extendingalong a longitudinal axis therethrough said longitudinal axis of saiddrill pipe body portion being generally parallel to a longitudinal axisof said generally deviated or horizontal section of said borehole, a cambody portion extending longitudinally along a length of said drill pipebody having a generally smooth cam arc section on an opening side withat least one elongated flat surface extending longitudinally along aclosing side of said cam body portion from a pin end tapering shoulderto a box end tapering shoulder, said cam body portion vertically liftinga generally horizontal drill pipe section of said drill stringvertically in said in said generally deviate or horizontal section ofsaid borehole when said drill pipe section is rotated in said borehole.7. A method of retrofitting a standard drill pipe section having a wearjoint to a vibratory drill pipe section comprising the steps of:obtaining said standard drill pipe section having a wear joint; cleaninga surface of said wear joint for attachment of profile members;attaching a cam-shaped profile member to said wear joint surface;attaching a flat profile member to said wear joint surface adjacent saidcam-shaped profile member; and; and providing generally smooth taperingshoulders at pin and box ends of said cam-shaped profile member and saidflat profile member to said wear joint surface.